Fluid flow measuring device and method

ABSTRACT

In a borehole logging tool, the flow of conductive fluid into or out of a wellbore at the wellbore wall is detected and measured with a sensor loop proximate the borehole inner wall. The sensor loop includes a series of contiguous sensors that act as electromagnetic flowmeters and provide fluid measurements covering the entire circumference of the sensor loop. The sensor loop includes an elastic element that forces the sensor loop outward to maintain pressure along the sensor loop circumference against the interior borehole wall. The sensor loop is designed to lie at a non-perpendicular angle to the wellbore axis, and mechanical arms press the top and bottom of the loop against the borehole inner wall.

This application is a continuation of U.S. patent application Ser. No.12/412,246, entitled “Fluid Flow Measuring Device and Method ofManufacturing Thereof,” filed on Mar. 26, 2009 now U.S. Pat. No.7,836,759; which is a continuation of U.S. patent application Ser. No.11/254,447, now U.S. Pat. No. 7,509,852 B2, entitled “Fluid FlowMeasuring Device and Method of Manufacturing Thereof,” filed on Oct. 20,2005 and issued on Mar. 31, 2009; which is a continuation of U.S. patentapplication Ser. No. 10/924,320, now U.S. Pat. No. 6,971,271 B2,entitled “Fluid Flow Measuring Device and Method of ManufacturingThereof,” filed on Aug. 23, 2004 and issued on Dec. 6, 2005; which is acontinuation of U.S. patent application Ser. No. 10/600,053, now U.S.Pat. No. 6,779,407 B2, entitled “Fluid Flow Measuring Device and Methodof Manufacturing Thereof,” filed on Jun. 20, 2003 and issued on Aug. 24,2004; which is a divisional of U.S. patent application Ser. No.09/880,402, now U.S. Pat. No. 6,711,947 B2, entitled “Conductive FluidLogging Sensor and Method,” filed on Jun. 13, 2001 and issued on Mar.30, 2004, all of which applications are incorporated herein byreference.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is related to the following co-pending andcommonly-assigned patent applications: U.S. patent application Ser. No.12/497,934, entitled “Apparatus and Method for Fluid Flow Measurementwith Sensor Shielding,” filed Jul. 6, 2009; and U.S. patent applicationSer. No. 12/513,807, entitled “Rotating Fluid Flow Measurement Deviceand Method,” filed Nov. 9, 2007 and having a section 371 date of May 6,2009.

TECHNICAL FIELD

This invention relates generally to oil and gas well production loggingsensors and methods, and more particularly to a sensing device andmethod for detecting fluid influx into a well.

BACKGROUND

An oil and gas well is shown in FIG. 1 generally at 60. Wellconstruction involves drilling a hole or borehole 62 in the surface 64of land or ocean floor. The borehole 62 may be several thousand feetdeep, and drilling is continued until the desired depth is reached.Fluids such as oil, gas and water reside in porous rock formations 68. Acasing 72 is normally lowered into the borehole 62. The region betweenthe casing 72 and rock formation 68 is filled with cement 70 to providea hydraulic seal. Usually, tubing 74 is inserted into the hole 62, thetubing 74 including a packer 76 which comprises a seal. A packer fluid78 is disposed between the casing 72 and tubing 74 annular region.Perforations 80 may be located in the casing 72 and cement 70, into therock 68, as shown.

Production logging involves obtaining logging information about anactive oil, gas or water-injection well while the well is flowing. Alogging tool instrument package comprising sensors is lowered into awell, the well is flowed and measurements are taken. Production loggingis generally considered the best method of determining actual downholeflow. A well log, a collection of data from measurements made in a well,is generated and is usually presented in a long strip chart paper formatthat may be in a format specified by the American Petroleum Institute(API), for example.

The general objective of production logging is to provide informationfor the diagnosis of a well. A wide variety of information is obtainableby production logging, including determining water entry location, flowprofile, off depth perforations, gas influx locations, oil influxlocations, non-performing perforations, thief zone stealing production,casing leaks, crossflow, flow behind casing, verification of new wellflow integrity, and floodwater breakthrough, as examples. The benefitsof production logging include increased hydrocarbon production,decreased water production, detection of mechanical problems and welldamage, identification of unproductive intervals for remedial action,testing reservoir models, evaluation of drilling or completioneffectiveness, monitoring Enhanced Oil Recovery (EOR) process, andincreased profits, for example. An expert generally performsinterpretation of the logging results.

In current practice, measurements are typically made in the centralportion of the wellbore cross-section, such as of spinner rotation rate,fluid density and dielectric constant of the fluid mixture. These datamay be interpreted in an attempt to determine the flow rate at any pointalong the borehole. Influx or exit rate over any interval is thendetermined by subtracting the flow rates at the two ends of theinterval.

In most producing oil and gas wells, the wellbore itself generallycontains a large volume percentage or fraction of water, but oftenlittle of this water flows to the surface. The water that does flow tothe surface enters the wellbore, which usually already contains a largeamount of water. The presence of water already in the wellbore, however,makes detection of the additional water entering the wellbore difficultand often beyond the ability of conventional production logging tools.

Furthermore, in deviated and horizontal wells with multiphase flow, andalso in some vertical wells, conventional production logging methods arefrequently misleading due to complex and varying flow regimes orpatterns that cause misleading and non-representative readings.Generally, prior art production logging is performed in these complexflow regimes in the central area of the borehole and yields frequentlymisleading results, or may possess other severe limitations. Often thelocation of an influx of water, which is usually the information desiredfrom production logging, is not discernable due to the small change incurrent measurement responses superimposed upon large variations causedby the multiphase flow conditions.

The problems of production logging in multi-phase flow in conventionalproduction logging are well known and described in the literature. Hill,A. D., et al., in an article entitled, “Production Logging Tool Behaviorin Two-Phase Inclined Flow”, JPT, October 1982, pp. 2432-2440, describethe problems of conventional production logging in multiphase wells,stating that for production logging purposes, a well is deviated if ithas a deviation over two degrees. Virtually all producing wells havedeviations of at least two degrees, and thus virtually all wells aresubject to difficult multiphase flow conditions for production logging.Hill et al. also describe the four main types of measurements in use inconventional production logging practice, which are the spinner,dielectric constant, fluid density, and concentrating flowmeter.

A more extensive description of conventional production loggingmeasurements and the problems encountered in multiphase flow is found ina monograph entitled “Production Logging—Theoretical and InterpretativeElements”, by Hill, A. D., Society of Petroleum Engineers, MonographVolume 14, Richardson, Tex., 1990. In addition, the followingpublications discuss the problems of measuring multiphase flow indeviated or horizontal wells: “Tests Show Production Logging Problems inHorizontal Gas Wells” by Branagan, P., et al., Oil & Gas Journal, Jan.10, 1994, pp. 41-45; “Biphasic Fluid Studies for Production Logging inLarge-Diameter Deviated Wells” by Kelman, J. S., November-December 1993,The Log Analyst, pp. 6-10; “A Comparison of Predictive Oil/Water HoldupModels for Production Log Interpretation in Vertical and DeviatedWellbores” by Ding, Z. X., et al, SPWLA 35th Annual Logging SymposiumTransactions, June 1994, paper KK; and “Production Logging in HorizontalWellbores” by Nice, S. B., 5th World Oil. Horizontal Well Technol. Int.Conf. (Houston) Proc., sect. 11, November 1993.

While very few wells are actually vertical, the following publicationillustrates that conventional production logging may be misleading evenin truly vertical wells: “The Effect of Flow From Perforations onTwo-Phase Flow: Implications for Production Logging” by Zhu, D., et al.,Proceedings SPE Annual Technical Conference and Exhibition, SPE 18207,October 1988, p. 267-75.

U.S. Pat. No. 5,551,287 entitled, “Method of Monitoring Fluids Enteringa Wellbore”, issued Sep. 3, 1996 to Maute et al. addresses the aboveproblems. However, the invention has limitations in that it ismechanically complex, and is sensitive in different ways to all threefluids encountered downhole (water, gas, and oil), which results incomplex log interpretation, and possibly misleading log interpretation.For example, the interpretation may be misleading if gas does not coolupon entry to the wellbore, as it usually but not always does. Theinterpretation is also complicated when the wellbore contains asignificant amount of non-produced water as is generally the case,making the distinguishing of inflow of water from non-produced waterdifficult and ambiguous. In addition, the tool is designed for only onecasing diameter, and cannot readily accommodate any significantlydifferent diameter, as does occur in many wells. Furthermore, a largeamount of data is needed from each of the multitude of pads (eight ormore), each of which has three different sensors.

SUMMARY OF THE INVENTION

The present invention provides an apparatus for and a method ofmeasuring the flow of fluid as it enters or exits a wellbore before itbecomes substantially intermixed with the fluids and the often complexflow pattern already in the wellbore.

In accordance with a preferred embodiment, a logging device utilizes asensor loop comprising a plurality of electrodes to sense the flow ofwater in a wellbore. The sensor loop may include a spring for exertingcontinuous pressure against the wellbore wall and includes at least onecurrent coil adapted to generate a magnetic field. By measuring thevoltage induced by the magnetic field and conductive fluid (e.g., water)movement within the wellbore perpendicular to the magnetic field, thelateral flow rate of the water can be determined. The logging device mayinclude at least two arms adapted to maintain the sensor loop forceagainst the wellbore wall while moving up and down within the wellbore,even with varying borehole diameters.

Disclosed is a preferred embodiment of a logging tool for a borehole,the borehole having an interior wall, the tool comprising a tool bodyadapted to be inserted into the borehole, and a radial sensing devicecoupled to the tool body, the radial sensing device adapted to measurethe flow velocity of conductive fluid entering or leaving the boreholeinterior wall, the radial sensing device being adapted to make theconductive fluid flow velocity measurements proximate the borehole wall.

Also disclosed is a preferred embodiment of a fluid flow measuringdevice, comprising a plurality of resistors disposed in a loop pattern,a plurality of electrodes, each electrode coupled between two adjacentresistors, a first coil of wire adapted to generate a magnetic fieldwound proximate the resistors and electrodes, a second coil of wireadapted to generate a magnetic field wound proximate the resistors andelectrodes, and a voltage measuring mechanism electrically coupledbetween two of the resistors, wherein a flow of conductive fluid isdetectable by measuring the voltage.

Further disclosed is a preferred embodiment of a method of measuringlateral fluid flow into a borehole, comprising traversing the boreholewith a tool body having a sensor loop attached thereto, wherein thesensor loop is adapted to directly measure the flow velocity ofconductive fluid entering or leaving the borehole interior wall.

Advantages of preferred embodiments of the invention include providing alogging device that is sensitive only to conductive fluids such aswater, and not sensitive to non-conductive fluids such as oil or gas.Only water entering or exiting the wellbore is sensed as it enters orexits, and the sensor loop is not sensitive to water already in theborehole, whether the water is moving or not. The device is notsensitive to the complex flow regimes in the center of the wellbore,because preferred embodiments of the invention measure the flow as itenters the wellbore along the wall and before it enters into the complexflow regimes in the wellbore center. Inferring the cause of changes inabove and below readings is not required as in the prior art; rather,the novel logging device directly senses water entering or leaving thewellbore. Also, the device is not required to infer the type of fluidentering the borehole, as preferred embodiments of the invention aresensitive only to conductive fluids. The measurement sensor loop has nomoving parts, as in some prior art logging instruments that comprisespinners, for example. The sensor loop has no threshold fluid velocitybelow which the measurement registers no flow; thus the sensor loop willsense even a small fluid flow. Preferred embodiments of the presentinvention provide a direct measurement of the information that mustgenerally be inferred by production engineers, that is, where water isentering the borehole.

BRIEF DESCRIPTION OF THE DRAWINGS

The above features of preferred embodiments of the present inventionwill be more clearly understood from consideration of the followingdescriptions in connection with accompanying drawings in which:

FIG. 1 shows an oil or gas well;

FIG. 2 illustrates a cross-sectional view of a wellbore with the sensorloop of a preferred embodiment of the present invention positionedwithin the wellbore;

FIG. 2A shows a perspective view of the sensor loop moving downholetowards a water inflow;

FIG. 2B shows the sensor loop positioned over a water inflow, and thussensing the water inflow, during its downhole movement;

FIG. 3 shows a logging tool in a casing of a given inner diameter;

FIG. 3A shows the logging tool in the same well in a casing with aninner diameter smaller than that of FIG. 3;

FIG. 4 depicts a side view of a side arm against the casing wall withthe upper part of the sensor loop passing through a recess in the sidearm;

FIG. 4A shows a view of the same items of FIG. 3 from outside the casinglooking radially inward;

FIG. 4B shows a view from the end of the logging tool of part of thesensor loop and a mechanism for attaching the sensor loop to the sidearm;

FIG. 4C shows the bottom of the sensor loop and the side arm;

FIG. 4D shows the bottom of the sensor loop and the side arm with aradial view from outside the casing;

FIG. 5 shows the fixed ends of the force arms at the tool body;

FIG. 5A shows the axially moving ends of the force arms at the toolbody;

FIG. 5B shows the slot in the tool body in which the moving ends of theforce arms move axially;

FIG. 5C shows the smooth hinge and junction of the force arms with theside arms;

FIG. 5D illustrates a side view of mechanical elements of a loggingtool;

FIG. 6 depicts a side view of the sensor loop riding over a protrusionfrom the casing into the wellbore;

FIG. 7 shows water flow through a magnetic field producing an inducedand measurable voltage;

FIG. 8 shows a perspective view of the sensor loop and its variouscomponents;

FIG. 8A shows a perspective view of how the water flow velocitymeasurement is made on one segment of the sensor loop;

FIG. 9 shows a schematic of the flow-measuring electrical circuit of thesensor loop;

FIG. 10A illustrates a top view of the sensor loop;

FIG. 10B shows a cross-sectional view of the sensor loop;

FIG. 11 shows an example of a log response chart; and

FIG. 12 illustrates a logging tool.

Corresponding numerals and symbols in the different figures refer tocorresponding parts unless otherwise indicated. The figures are drawn toclearly illustrate the relevant aspects of the preferred embodiments,and are not necessarily drawn to scale.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

There are many disadvantages in prior art methods and tools fordetecting water flow. For example, prior art devices and techniques aresensitive to all fluids, including water, oil and gas, which leads toambiguity in the determination of what fluid is involved. Fluid entry orexit must be inferred from the wellbore from measurements made in thecenter of the borehole in complex and changing flow regimes above andbelow the point of interest, and the assumption that any change is dueto inflow or outflow must be made. Prior art methods do not directlysense water entering or leaving the wellbore, and are sensitive to wateralready in the borehole, whether the water is moving or not. Thedetermination of which type of fluid, water, oil or gas, is entering orexiting the borehole must be inferred by looking at changes inmeasurements made above and below the entry or exit and inferring whichtype of fluid made the changes. The measurements are made in the centerof the borehole in complex and changing flow regimes, which results inambiguity of interpretation.

In prior art designs, the measurement device typically has moving parts,such as a spinner, which is also called the flowmeter. These movingparts may become jammed with debris in the wellbore flow stream andbecome useless at times. A spinner is sensitive to moving water alreadyin the borehole, and has a threshold fluid velocity below which thespinner registers no flow, even though a small flow is present. Priorart measurement tools do not directly measure where water is enteringthe borehole.

Preferred embodiments of the present invention eliminate these problemsin the prior art by directly measuring water inflow or outflow throughthe borehole or casing wall. Preferred embodiments of the presentinvention may provide the depths and rates of water inflow or outflow.Almost all inflow or outflow is one phase, and so the flow is measuredbefore it can combine into complex flow patterns with other phases.Preferred embodiments of the present invention are thus insensitive tothe complex multiphase flow patterns found inside the wellbore.Preferred embodiments of the present invention also are sensitive toonly lateral water flow into or out of the wellbore, and are notsensitive to water flow up or down inside the wellbore. Preferredembodiments of the invention may also accommodate changes in thewellbore inner diameter. Preferred embodiments of the invention areinsensitive to the flow of oil or gas, allowing certain determination ofthe inflow or outflow of water, which is usually the information desiredto be obtained from production logging.

Preferred embodiments of the present invention will next be describedwith reference to FIGS. 2 through 11. Referring first to FIG. 2, alogging tool 140 includes a main tool body 101 and two centralizing sidearms 102 and 103. The tool body 101 preferably comprises steel and mayalternatively comprise titanium, as examples. The tool body 101 may be 8feet long and 1 inch wide, for example. The side arms 102/103 preferablycomprise steel and may alternatively comprise titanium, as examples. Theside arms 102/103 may be 5 feet long and ½ inch wide, for example. Theside arms 102 and 103 are forced against the wellbore 111 a or casing111 b by force arms 104, 105, 106, and 107. Force arms 104/105/106/107preferably comprise spring stainless steel, as an example. The forcearms 104/105/106/107 may be 1 feet long and ⅛ inch wide, for example.The wellbore 111 a is also referred to interchangeably herein as aborehole. Typically, a wellbore 111 a is lined with a casing 111 b forthe entire well. Embodiments of the present invention may be utilized ineither a cased wellbore or in an openhole wellbore with no casing, forexample.

In accordance with a preferred embodiment of the present invention, aradial sensing device 108 preferably comprising a sensor loop may beattached at radial sensing device 108 upper and lower ends to the twoside arms 102 and 103. An electrical line or slickline 109 may becoupled to the logging tool 140 and may be adapted to transport thelogging tool 140 to and from the surface. The electrical line 109 maytransmit electrical power down to the logging tool 140 and may transmitthe measured voltage to a voltage measuring and recording device 110 onthe land surface. Note that the measuring and recording device 110 mayalternatively reside within the logging tool body 101 as a memorydevice, and the tool 140 may be operated with an internal electricalpower source, such as batteries.

FIG. 2A illustrates a perspective view of the sensor loop 108 positionedagainst the inside of the casing 111 b wall, the sensor loop 108 beingadapted to move upward and downward over perforation holes 112 throughthe casing 111 b towards an inflow of water 113 through a perforationhole 112. In an oil or gas well, water inflow is undesirable, thereforethe location of the water inflow is important information to obtain sothat the casing 111 b can be repaired, for example. No inflow of wateris measured in the sensor loop 108 position shown in FIG. 2A becausethere is no inflow of water 113 anywhere over the sensor loop 108.Preferably, the sensor loop 108 remains flush with the casing 111 b orwellbore 111 a interior wall, to maintain close proximity to regions ofinflow of water 113, in order to directly sense the inflow of water 113.FIG. 2B shows the sensor loop 108 against the inside of the casing wall111 b moving downward and actually at the location of the inflow ofwater 113 through a perforation hole 112. In this position the sensorloop 108 detects the inflow of water 113.

An embodiment of the present logging tool 140 is adapted to measure thelocation and flow rate of a conductive fluid such as water entering orleaving a wellbore 111 a or other flow conduit, such as a water pipelineor a chemical line or a sewer line. Sensor loop 108 is preferablymounted on a logging tool body 101 such that the sensor loop 108 isforced radially against the inside of the wellbore 111 a or casing 111 bwall. The sensor loop 108 is designed such that it lies approximately ina plane, the plane preferably being oriented at a non-perpendicularangle (e.g., ranging from 10 to 80 degrees, and more preferably,approximately 45 degrees) to the borehole central axis. When insertedinto a borehole, the loop 108 may not lie completely in a plane due toit being compressed to fit within the borehole.

FIGS. 3 and 3A depict the present logging tool 140 in use withindifferent diameter casings 111 b, which may be located within the samewell, for example. The sloped force arms 104/105/106/107 allow the tool140 to enter smaller diameter casings 111 b, forcing the side arms102/103 closer to the tool body 101. The tilt or angle of the sensorloop 108 with respect to the borehole central axis changes from onecasing 111 b inner diameter to another, as seen from FIG. 3 to FIG. 3A.The sensor loop 108 preferably is substantially close to lying within asingle plane, but sensor loop 108 may not necessarily always lie exactlyin a plane, depending upon the diameter of the casing 111 b.

The top 108 a and bottom 108 b of the sensor loop 108 are held againstthe inner wall of the borehole 111 b. A preferred method of holding thetop 108 a and bottom 108 b of the sensor loop 108 against the inner wallor casing 111 b of the borehole is to mount the top 108 a and bottom 108b of the sensor loop 108 on each of two side arms 102 and 103,respectively, as shown in FIGS. 3 and 3A. The side arms 102/103 arepositioned substantially parallel to the main body 101 of the tool 140and are pressed flat against the inner casing 111 b wall. The two sidearms 102/103 are forced against the casing 111 b wall along their entirelength, such as by force arms 104/105/106/107 which act as bow-springcentralizers at the end of each side arm 102/103. The remainder of thesensor loop 108 substantially everywhere on its circumference forcesitself, by virtue of the elasticity of the sensor loop 108, to liesubstantially flush against the inner wall of the casing 111 b.

FIG. 4 shows a side view of the mounting of the sensor loop 108 at eachof the side arms 102/103 according to an embodiment of the presentinvention. The sensor loop 108 is preferably mounted to the side arm 102in a recess 114 within the side arm 102. The recess 114 preferably hasgently sloping ends at 114 a to allow space for the thickness of thesensor loop 108 within the side arm 102 and to avoid the tool hanging upon any protrusion from the casing. The recess 114 with sloping ends 114a allows the side arm 102 to ride substantially flush to the casinginner wall 111 b. A rolling mechanism 118 which may comprise, forexample, ball rollers or other rolling mechanism, may be used to reducewear on the side arm 102 and friction when the logging tool 140 movesalong the casing inner wall 111 b. Ball rollers 118 preferably comprisesteel and may alternatively comprise titanium, as examples. Ball rollers118 may be ¼ inch in diameter, for example.

The sensor loop 108 may be mounted to the side arm 102 with an alignmentpin 116. Alignment pin 116 preferably comprises steel and mayalternatively comprise titanium, as examples. Alignment pin 116 may be ½inch long and ⅛ inch in diameter, for example. Alignment pin 116preferably is coupled to the sensor loop 108 and resides within a slot115 in the side arm 102. Slot 115 may be 4 inches long, for example. Thealignment pin 116 is adapted to maintain the plane of the sensor loop108 relative to the logging tool 140 and is adapted to prevent the planeof the sensor loop 108 from rotating. The slot 115 in the side arm 102preferably has sloped ends, as shown, to allow some tilt by the sensorloop 108 cross-section if needed to free the sensor loop 108 from asnag. A slide ring 117 may be disposed around the side arm 102 coupledto the sensor ring 108 and alignment pin 116, the slide ring 117 beingadapted to maintain the sensor loop 108 substantially against the sidearm 102 within recess side arm 114 but allowing the sensor loop 108 tomove up or down along the side arm 102 within recess 114 as needed whenentering a different inner diameter casing 111 b. Slide ring 117preferably comprises steel and may alternatively comprise titanium, asexamples. Slide ring 117 may be ⅛ inch thick and ⅜ inch in diameter, forexample.

FIG. 4A shows side arm 102 and the upper end of the sensor loop 108 froma view outside the casing 111 b looking radially inward. The slot 115 inthe side arm 102 for the alignment pin may be seen within side armrecess 114, as well as the roller balls 118 in the side arm 102.

FIG. 4B shows a view of the sensor loop mounting mechanism from eitherend of the side arm 102. The alignment pin 116 coming out of the sensorloop 108 is shown with the slide ring 117. The side arm 102 may besubstantially cylindrical in shape, but may also comprise other shapes.

FIG. 4C illustrates the mounting of the sensor loop 108 on the side arm103, similar to FIG. 4, except FIG. 4C shows the other side arm 103.Again, the sensor loop 108 is mounted to the side arm in a recess 114within the side arm 103. This mechanism allows the side arm 103 to ridesubstantially flush to the casing 111 b inner wall. Ball rollers 118 oran alternative rolling mechanism may be used to reduce wear on the sidearm 103 and friction when the logging tool 140 moves along the casing111 b inner wall. The sensor loop 108 is preferably mounted with analignment pin 116 coupled to the sensor loop 108 and running out thesensor loop 108 and through a slot 115 in the side arm 103. Thealignment pin 116 maintains the plane of the sensor loop relative to thelogging tool and prevents the plane of the sensor loop from rotating.The slot 115 in the side arm 103 preferably has sloped ends as shown toallow some tilt by the sensor loop 108 cross section if needed to freethe sensor loop 108 from a snag. The slide ring 117 maintains the sensorloop 108 substantially against the side arm 103 within recess 114 butallows the sensor loop 108 to move up or down along the side arm 103within recess 114 as needed when entering a different inner diametercasing 111 b. An optional shield 114 a, comprising a fluoropolymerresin, and alternatively comprising nylon, for example, may be coupledto the side arm 103 to cover the recess 114 and prevent the sensor loop108 from snagging on protrusions along the casing 111 b wall.

FIG. 4D shows side arm 103 and the lower end of the sensor loop 108 froma view outside the casing looking radially inward. The slot 115 in theside arm 103 for the alignment pin is visible within the recess 114.Roller balls 118 in the side arm 103 are also visible.

FIG. 5 shows the fixed force arms 119 coupled to one end of the toolbody 101. Preferably, the force arms 119 at one end of the logging tool140 are fixed firmly to the tool body 101 to maintain the two side arms102/103 and the tool body 101 in one plane. The force arms 119 providean outward force to force the side arms 102/103 against the inner wallof the casing 111 b. The outward force may be achieved from theelasticity of the metal force arms 119, or from spring loading or othermechanisms, for example.

FIG. 5A illustrates the moving force arms 120 at the opposite end of thelogging tool 140 from the fixed force arms 119 at the other end of thetool 140. Force arms 120 also push the side arms 102/103 outward andagainst the casing 111 b inner wall. Preferably, by the geometry of thetool 140 design, the force arms 120 on at least one end of the tool 140are adapted to move axially, e.g., along the axis of the wellbore withinthe borehole 111 a, to allow for entry of the logging tool 140 intodifferent inner diameter casings 111 b. The moving force arms 120 may becoupled firmly to a thin flat plate or pin 121 a that moves axially in aslot 121 through the tool body 101, for example (not shown).Alternatively, the force arms 120 may be fixed at both ends, moveable atboth ends, or movable at the top and fixed at the bottom.

FIG. 5B shows a side view of the tool body 101 (oriented 90 degrees tothe view of FIG. 5A). The slot 121 is shown that the plate or pin 121 acoupled to the moving force arms 120 is adapted to move within. Pin 121a preferably comprises steel and may alternatively comprise titanium, asexamples. Pin 121 a may be ¾ inch long and ⅛ inch in diameter, forexample.

FIG. 5C demonstrates a preferred method of connecting a force arm to asidearm, in this case force arm 104 to side arm 102. Force arm 104 isconnected to side arm 102 with a smooth hinge 122, such that no lipexists anywhere to hang up the tool 140 when the force arm 104 enters asmaller diameter casing 111 b. Hinge 122 preferably comprises steel andmay alternatively comprise titanium, as examples. Hinge 122 may be ½inch in width and 4 inches in length, for example.

When the logging tool 140 enters a larger diameter casing 111 b, such asgoing out of tubing and into larger diameter casing, the force arms 119and 120 push the side arms 102/103 radially outward to contact thelarger diameter borehole 111 b. The moving end of the force arms 120slides in its slot 121 towards the fixed end of the force arms 119.Similarly, when the tool 140 enters a smaller diameter portion of thewellbore 111 b, the slope of the force arms 119 or 120 in contact withthe end of the new diameter tubular 111 b causes a radially inward forceon the force arms 119 or 120 which compresses the force arms 119 or 120radially towards the tool body 101. The moving force arms 120 move inslot 121 axially away from the fixed end force arms 119. Once in the newdiameter casing 111 b or borehole 111 a, be it larger or smaller, theside arms 102/103 are forced by the force arms 119/120 to becomesubstantially flush with the new borehole 111 a or 111 b wall.

FIG. 5D illustrates a cross-sectional view of the logging tool 140 withthe sensor ring 108 coupled to the side arms by alignment pin 116 (notshown) and slide ring 117, within slot 115 in side arms 102/103. Sidearms 102/103 are coupled to force arms 119, which force arms 119 arefixably coupled to tool body 101. At the other end of the tool 140, sidearms 102/103 are coupled to force arms 120, which force arms 120 aremoveably coupled to tool body 101 within tool body slot 121 by plate/pin121 a. As the tool 140 is moved to a portion of the borehole 111 ahaving a smaller diameter, dimension x is decreased, while dimension yincreases, and the angle of the sensor loop 108 to the central axis ofthe borehole 111 a is decreased, accordingly.

Preferably, the force arms 119/120 at either end of the two side arms102/103 are tapered towards the main body 101 of the tool 140 to allowthe arms 102/103 to move radially in or out, in conformance with anychanges in the inner diameter of the wellbore 111 a or casing 111 b. Asthe side arms move radially in or out to a wall with a differentdiameter, the side arms move the top and bottom of the sensor loop 108in or out, also. The sensor loop 108 forces itself substantiallyeverywhere against the inside of the wall 111 a/111 b with the newdiameter. Thus, preferred embodiments of the present invention 140 mayaccommodate various wall 111 a/111 b diameters within one well.

FIG. 6 demonstrates that the sensor loop body 136 cross-section may besloped at an angle with respect to the casing wall 111 b to enable thesensor loop 108 to ride over small protrusions 123 extending out of thecasing wall 111 a. This is advantageous because it will prevent the tool140 from hanging up during logging.

FIG. 7 illustrates the water flow measurement physics principleimplemented by the radial sensing device 108 of a preferred embodimentof the present invention, which is based upon Faraday's law of inducedvoltage. A magnetic field 128 substantially perpendicular to a flow 113of water or other conductive liquid generates a voltage difference 133perpendicular to both the magnetic field 128 and the water flowdirection 113. This induced voltage 133 is detectable with a pair ofelectrodes 129 coupled by wires 130 to a measuring device 110 which maycomprise a voltmeter, for example. Preferably an alternating magneticfield 128 is used which results in an alternating measured voltage 133.Using an alternating magnetic field 128 reduces the effects of electrodepolarization and voltages resulting from complex electrochemicalprocesses.

The electrodes 129 are positioned along the sensor loop 108, acting assensors, with each pair of sensors comprising a small electromagneticflowmeter. An electromagnetic flowmeter is a flow measurement method,the method comprising placing a magnetic field 128 at right angles tothe flow 113 of a conductive fluid and then measuring the voltage 133between the flowmeters. In a preferred embodiment of the presentinvention, the magnetic field 128 is at right angles to a casing 111a/111 b diameter of the sensor loop 108 through the water inflow/outflowlocation. Water has the necessary conductivity to be measured, but oiland gas do not. Therefore, preferred embodiments of the presentinvention are insensitive to the flow of oil or gas, and sensitive onlyto the flow of water flowing radially inward or outward of the wellbore.Preferred embodiments of the present invention are not sensitive to theflow of water inside the wellbore along the axis of the borehole 111a/111 b, whether that water is moving towards the top or the bottom ofthe well. When water flows through the magnetic field 128, a voltage 133is induced perpendicular to the magnetic field 128 and perpendicular tothe diameter along which the water enters the wellbore 111 a/111 b. Twoelectrodes 129 or sensors on either side of the water flow 113 detectthis voltage 133. This induced voltage 133 is directly proportional tothe water fluid 113 velocity, and reverses in sign if the water flow isout instead of in.

FIG. 8 shows a preferred embodiment of the sensor loop 108 adapted tomake a voltage measurement described herein. The sensor loop 108 ispositioned substantially flush to the casing 111 b. The sensor loop 108comprises a sensor loop body 136. The sensor loop body 136 preferablycomprises fluoropolymer resin and may alternatively comprise nylon, asexamples. The sensor loop body 136 may be ¼ inch wide, ⅜ inch long, and24 inches in diameter, for example.

The sensor loop body 136 preferably encloses two coils of wire 125 and126, the coils 125/126 being adapted to carry current to induce amagnetic field 128. Coils 125/126 preferably comprise a copper alloy,and may alternatively comprise other conductive materials such asaluminum, as examples.

The magnetic field 128 is generated by a current run through the twocoils 125/126 of wire in the sensor loop 108, each coil 125/126 runningaround the entire length of the sensor loop. The two coils 125/126 carrycurrent in opposite directions so that the magnetic field from each coil125/126 is in the same direction between the coils 125/126, and tends tocancel inside the inner coil 125 and outside the outer coil 126. A softferromagnetic material 127 is preferably positioned between the coils125/126, the ferromagnetic material 127 adapted to increase the strengthof the magnetic field 128 between coils 125/126. Ferromagnetic material127 preferably comprises an iron alloy, and may alternatively compriseother magnetic materials such as nickel, as examples. The ferromagneticmaterial 127 may be ⅛ inch wide, for example.

Electrodes 129 are coupled along the exterior of the sensor loop body136 and are adapted to detect a voltage difference between each adjacentpair of electrodes 129. Electrodes 129 preferably comprise a copperalloy, and may alternatively comprise other conductive materials such asaluminum, as examples. Electrodes 129 may be ⅛ inch wide and ⅛ inchlong, for example.

The sensor loop 108 is spring-loaded, which feature is accomplished bythe sensor loop 108 comprising a spring or force loop 124 being adaptedto exert outward pressure to maintain contact of the sensor loop 108substantially flush with the borehole interior wall while the tooltraverses the borehole. Force loop 124 preferably comprises an elasticmaterial, such as stainless steel spring wire, and may alternativelycomprise bronze. The force loop 124 is preferably imbedded in the sensorloop body 136 to provide a mechanical force to press the sensor loop 108substantially everywhere against the inside wall of the wellbore 111 aor casing 111 b regardless of the bore or casing interior diameter.

The electrodes 129 are preferably spaced equidistant from one another,at regular spacings, with each spacing distance preferably beingsomewhat about or less than the diameter of a perforation hole 112(shown in FIG. 8A). Electrodes 129 are contiguous to each other and ringthe entire sensor loop 108 to cover the full circumference of the sensorloop 108 and thus the full interior of the casing 111 b wall. Oneelectrode 129 can act as the right electrode for a pair of electrodesand also simultaneously act as the left electrode for the next adjacentpair, so that a series of substantially equally spaced electrodes 129exists at the surface of the sensor loop 108. These electrodes 129 arepreferably coupled in series to each other with a high value resistor(shown in FIG. 9) between each. If the total voltage between one pair ofelectrodes 129 without an intervening resistor 132 is measured andrecorded (e.g., by voltage meter 110, shown in FIG. 9), this voltage 133is indicative of the fluid flow 113 rate (shown in FIG. 8 a). Preferablythe pair of electrodes 129 without an intervening resistor 132 are inclose proximity to one another to minimize the amount of insensitivemeasuring length between them.

The measured voltage 133 is proportional to the equivalent flow velocitythrough one perforation hole 112 (shown in FIG. 8 a). If the perforationhole 112 diameter is known (from known information about the type ofcharge that made it) or estimated (typically 0.3 inches in diameter, forexample), the inflow or outflow rate at that depth within the well mayalso be determined.

In a preferred embodiment, the magnetic field 128 is alternating ratherthan constant to achieve optimum logging results. An alternatingmagnetic field minimizes electrode 129 polarization effects and alsominimizes effects of voltages induced by complex chemical and otherprocesses. Thus, an alternating electrical current may be applied to thecoils to obtain an alternating magnetic field 128.

FIG. 8A shows the measurement of water flow 113 with the sensor loop 108in accordance with an embodiment of the present invention. The magneticfield 128 is substantially perpendicular to water flow 113 moving into,or out of, the wellbore 111 b. An induced signal voltage 133 isgenerated and detected by a pair of electrodes 129 if a conductive fluidsuch as water is flowing substantially radially inward or outward of thewellbore 111 b. The sensor loop 108 is sensitive only to water flowingradially. Radial inflow is distinguished from radial outflow by the sign(e.g., +/−) of the signal voltage 133. Advantageously, the presentsensor loop 108 is not sensitive to axial flow in the wellbore.Additionally, since the measurement principle requires some small amountof fluid conductivity as virtually all water has, oil and gas flows willnot be detected as they are insulators and do not have the requiredminimum amount of conductivity. Thus the sensor loop 108 is sensitiveonly to the flow of conductive fluids such as water, and only to lateralconductive fluid that is entering or leaving the wellbore 111 b. Incontrast, prior art techniques are also sensitive to fluid movementinside the wellbore, and are sensitive to non-conductive fluid movementsuch as oil and gas.

FIG. 9 shows a schematic of some electrical components within the sensorloop 108. The electrodes 129 are coupled to a resistor network. Theelectrodes 129 are coupled together with high resistance value resistors132 such that measured voltage, measured by voltage measuring device110, is proportional to the fluid flow 113 velocity, if the flow ispassed over or between at least one pair of electrodes 129. Resistors132 preferably range from 500,000 to 2,500,000 ohms and more preferablycomprise 1,000,000 or 2,000,000 ohm resistors, as examples. The flowrate 113 is proportional to the measured voltage 133.

FIG. 10A illustrates a top view of the sensor loop 108, including asensor loop body 136 which contains or is coupled to the sensor loop 108elements described previously herein. FIG. 10B shows an example of across-sectional view of the sensor loop 108.

If the orientation of the inflow or outflow is desired, as would beuseful in various applications, an alternative wiring and data samplingof the sensor loop 108 may be implemented, whereby each electrode 129pair by itself is measured along with the azimuthal angle of the highside of the tool measurement. Thus, the orientation of the inflow oroutflow may be determined.

FIG. 11 shows an example log 150 indicating the response of the presentlogging device described herein. On the log, the x-axis represents depthin feet, and the y-axis represents water flow rate in barrels of waterper day. When preferred embodiments of the present invention are loweredinto this wellbore over the interval 7000 to 7100 feet, a water inflowinto the wellbore is detected at 7060 feet, shown at 152, in thisexample. No water inflow is detected except at 7060 feet, as evidentfrom the logging graph 150.

While preferred embodiments of the invention are described withreference to oil and gas wells and water-injection wells, preferredembodiments of the present logging device are also useful in detectingleaks in water pipelines and other fluid pipelines, for example. Otheralternative elements and features may be utilized with the presentlogging device. For example, an electromagnetic flow measurement in someother mode may be implemented, such as one pair of electrodes 162 on arotating arm 102 to sweep around the casing inner wall, as shown bylogging tool 160 in FIG. 12. A different arrangement may be used to holdthe sensor loop against the borehole wall, such as a telescoping loop,where the loop is perpendicular to the casing axis, adapted to flip downinto place after going below the tubing. Another means of holding thesensor loop against the borehole wall may include a three or four pointhold against the casing inner wall instead of the two point holddisclosed. Rather than making the water flow measurement directlyagainst the borehole wall, the measurement may be made a predetermineddistance away from the casing inner wall, e.g., ⅛″ to ¾″. The loggingdevice design may be simplified to accommodate only one casing diameter,resulting in a simpler tool design. Rather than comprising a sensor loopas described herein, the radial sensing device 108 may alternativelycomprise a plurality of small individual electromagnetic sensors 162,164 (e.g. one electrode pair) used on each arm 102, 103 of amultiply-armed caliper tool 160, although the sensors may not cover thefull borehole wall circumference in some cases. The preferredembodiments of the present invention are described herein for themeasurement of the lateral inflow and outflow of water, however,preferred embodiments of the invention may also be utilized to measurethe lateral flow of other conductive fluids. The various exampledimensions described herein may vary according to a variety of factorssuch as how large the borehole is, and the inner diameter dimensions ofthe casings and tubing within the borehole.

The novel logging device embodiments disclosed herein achieve technicaladvantages by providing a logging device that is sensitive only to aconductive fluid such as water, and that is not sensitive tononconductive fluids such as oil or gas. Only water entering or leavingthe wellbore is sensed as it enters or leaves, and the sensor loop isnot sensitive to water already in the borehole, whether the water ismoving or not. The device is not sensitive to the complex flow regimesin the center of the wellbore, because the device measures the flow asit enters the wellbore along the wall and before it enters into thecomplex flow regimes in the wellbore center. The device is not requiredto infer the cause of changes in above and below readings. The novellogging device directly senses water entering or leaving the wellbore.The device is not required to infer the type of fluid entered theborehole, as preferred embodiments of the invention are sensitive onlyto water. The measurement sensor loop has no moving sensor parts, as insome prior art logging instruments that comprise spinners, for example.The sensor loop has no threshold fluid velocity below which themeasurement registers no flow, thus it will sense even a small flow.

While most prior art logging devices must be passed through the wellboremore than once, e.g., typically six sets of readings to obtain anaccurate reading, preferred embodiments of the present invention mayprovide an accurate reading in only one pass, e.g., one set of readings.For example, the logging device 140 need only be inserted once into theborehole, and then removed, resulting in each portion of the boreholebeing measured for conductive fluid flow as little as once and beingtraversed only twice. Additionally, varying diameters of borehole may beaccommodated with preferred embodiments of the present invention, withthe use of the side arms that automatically adjust the angle of thesensor loop with respect to the borehole central axis.

While preferred embodiments of the invention have been described withreference to illustrative embodiments, this description is not intendedto be construed in a limiting sense. Various modifications incombinations of the illustrative embodiments, as well as otherembodiments of the invention, will be apparent to persons skilled in theart upon reference to the description. In addition, the order of processsteps may be rearranged by one of ordinary skill in the art, yet stillbe within the scope of preferred embodiments of the present invention.It is therefore intended that the appended claims encompass any suchmodifications or embodiments. Moreover, the scope of the presentapplication is not intended to be limited to the particular embodimentsof the process, machine, manufacture, composition of matter, means,methods and steps described in the specification. Accordingly, theappended claims are intended to include within their scope suchprocesses, machines, manufacture, compositions of matter, means,methods, or steps.

1. A method of measuring radial fluid flow in a casing having aninterior wall, the method comprising: inserting a tool body into thecasing, wherein the tool body comprises an arm with an electromagneticsensing device attached to a distal end thereof, and wherein anelectrical line is coupled to the tool body; transmitting electricalpower to the tool body via the electrical line; axially traversing thecasing with the tool body; azimuthally rotating the arm to sweep theelectromagnetic sensing device around the casing interior wall; sensingfor a radial flow of conductive fluid through the casing interior wallwith the electromagnetic sensing device; and receiving and recordinginformation regarding the radial flow of conductive fluid, from theelectromagnetic sensing device via the electrical line.
 2. The method ofclaim 1, wherein the electromagnetic sensing device comprises a pair ofelectrodes, and wherein the sensing for the radial flow of conductivefluid comprises: generating a magnetic field perpendicular to animaginary line between the pair of electrodes, and perpendicular to theradial flow of conductive fluid; and measuring a voltage differencebetween the pair of electrodes.
 3. The method of claim 2, wherein thevoltage difference is proportional to a velocity of the radial flow ofthe conductive fluid proximate the pair of electrodes.
 4. The method ofclaim 1, wherein the azimuthally rotating the arm further comprisesmaintaining the electromagnetic sensing device in contact with thecasing interior wall.
 5. The method of claim 1, wherein the sensing forthe radial flow of conductive fluid comprises measuring with theelectromagnetic sensing device within a distance of 0.75″ from thecasing interior wall.
 6. The method of claim 1, wherein the insertingthe tool body into the casing further comprises: compressing the distalend of the arm toward a center axis of the tool body; inserting the toolbody into a tubing disposed within the casing; and expanding the distalend of the arm away from the center axis of the tool body as the toolbody exits the tubing.
 7. The method of claim 1, wherein the sensing forthe radial flow of conductive fluid further comprises sensing as thetool body traverses the casing away from an insertion point.
 8. Themethod of claim 1, wherein the sensing for the radial flow of conductivefluid further comprises sensing as the tool body traverses the casingtoward an insertion point.
 9. A method of measuring radial fluid flow ina casing having an interior wall, the method comprising: inserting alogging tool into the casing, wherein an electrical line is coupled tothe logging tool; transmitting electrical power to the logging tool viathe electrical line; traversing the casing with the logging tool;generating a magnetic field perpendicular to a sensor disposed on thelogging tool, and perpendicular to a radial flow of conductive fluidthrough the casing wall, wherein the sensor is disposed perpendicular tothe radial flow of conductive fluid; positioning the sensor adjacent tothe casing interior wall; directly sensing the radial flow of conductivefluid through the casing wall with the sensor; receiving informationrepresentative of the radial flow of conductive fluid, from the sensorvia the electrical line; and recording the information representative ofthe radial flow of conductive fluid.
 10. The method of claim 9, whereinthe generating the magnetic field comprises generating an alternatingmagnetic field.
 11. The method of claim 9, further comprising generatinga logging graph of a casing position versus an amount of the radial flowof conductive fluid, from the information received from the sensor. 12.The method of claim 11, wherein the position comprises a depth in thecasing.
 13. The method of claim 11, wherein the position furthercomprises an azimuthal orientation in the casing.
 14. The method ofclaim 9, wherein the sensor comprises a pair of electrodes, and whereinthe generating the magnetic field further comprises generating themagnetic field perpendicular to an imaginary line between theelectrodes.
 15. The method of claim 9, wherein the sensing the radialflow of conductive fluid further comprises sensing as the logging tooltraverses the casing away from an insertion point.
 16. The method ofclaim 9, further comprising removing the logging tool from the casingafter traversing the casing.
 17. A method of measuring radial fluid flowin a casing having an interior wall, the method comprising: inserting adetection tool having a sensor into the casing, the sensor having a pairof electrodes; traversing the casing with the detection tool;positioning the sensor adjacent to the casing interior wall; generatingan electromagnetic field having an orientation such that theelectromagnetic field, a radial flow of conductive fluid through thecasing wall, and an imaginary line interconnecting the pair ofelectrodes are all orthogonal to each other; directly detecting theradial flow of conductive fluid through the casing wall with the sensor;and recording data related to the radial flow of conductive fluiddetected by the sensor.
 18. The method of claim 17, wherein thedetection tool is coupled to an electrical line, and wherein the methodfurther comprises: providing electrical power to the detection tool viathe electrical line; and transferring the data related to the radialflow of conductive fluid from the sensor to a remote recording devicevia the electrical line.
 19. The method of claim 17, further comprisingrecording a casing positional information of the detection tool in thecasing.
 20. The method of claim 19, further comprising graphicallyplotting the casing positional information versus an amount of theradial flow of conductive fluid, from the data transferred from thesensor.
 21. The method of claim 19, wherein the casing positionalinformation comprises a depth in the casing.
 22. The method of claim 19,wherein the casing positional information comprises an azimuthalorientation in the casing.
 23. The method of claim 17, wherein the datarelated to the radial flow of conductive fluid comprises a signalrepresentative of a voltage level proportional to a radial flow rate ofthe conductive fluid.
 24. The method of claim 17, wherein the generatingthe electromagnetic field comprises generating an alternatingelectromagnetic field.
 25. The method of claim 17, wherein the sensor iscoupled to a body of the detection tool by an arm, and wherein themethod further comprises rotating the arm to sweep the sensor around theinterior wall of the casing.
 26. The method of claim 25, furthercomprising exerting pressure radially outward on the casing wall withthe arm.